Cold Stacked but Ready-to-Drill

Is it true that a modern cold stacked rig cannot be “Ready to Drill”?

The very term “Cold Stack” conjures up images of rusting frozen up equipment, though experience with aviation and military proves that cold mothballed equipment can be mobilized and ready to use within a day.

There is another term being used these days, “Smart Stacked”, which implies only partial cold shut down. A potentially more effective way to keep rigs drill ready and in survey. Smart Stack implies a very active rig crew looking after several idle rigs at once. In general, wherever possible, systems are cold mothballed using Volatile Corrosion Inhibitors (VCIs) to protect tanks, cooling systems, pipes, engines, hydraulic units and electrical panels.
We looked at this in The Way we Preserve our Assets is Costing us Millions.

To keep a vessel in class survey, certain systems have to be tested and inspected on a regular basis. In these difficult times, we should be looking at how to carry out these tests using our own (fully certified) people, instead of paying big fees to third parties.

Senior rig maintenance person Kenneth Roberts pointed out in a recent comment on Oilpro.com that: “Taking some of these API RP documents that deal with maintenance and inspection as absolute requirements hinders the development and implementation of sound maintenance programs and condition monitoring systems. This can and does lead to unnecessary waste of money and time while not enhancing safety at all. In fact disturbing equipment unnecessarily can lead to premature failure and reduced safety.”

We can still comply with the *intent* of a Recommended Practice by having a qualified third party witness our own in-house tests, rather than having the third party do the tests themselves. Wire rope certification works this way.

While this may not be what exactly what some rules intended, there have been enough cases where exemptions are granted. For example, the rules may require certain systems to be inspected and tested by the OEM (Original Equipment Manufacturer). We have had cases when we could show that the China manufacturer could not send English speaking technicians, in which case, regulators allowed a local certified party to do the tests and inspections. This has recently been the case with tests of China made lifeboats and lifeboat davits.

When we read though many of the latest rules and recommended practices, we can see that some were drafted in the days when the only way to confirm the good condition of a machine was to open the cover and physically inspect the internal parts. Indeed , not long ago, we had a young surveyor from a well known marine classification society visiting a rig a for it’s 5 year survey; he wanted to insist on removing the cylinder heads from a modern Caterpillar diesel engine to inspect the interior condition, a practice which Caterpillar themselves stopped recommending over 40 years ago.

In other words, class rules are meant to convey an intent, as much as a particular specific requirement. This can be frustrating to explain to a still wet-behind-the-ears young graduate engineer, who wants to blindly follow the written word, without looking through the words to see the intent behind those literal words.

With this in mind, we are certainly within our rights to negotiate with class surveyors innovative ways to comply with class requirements, such as expanding the use of ultrasonic tests. Acoustic Emission (AE) Non Destructive Evaluation (NDE) techniques confirm that systems are in safe condition, without the risk and expense of physically dismantling critical components.

Usually a phone call to a young surveyor’s boss, e.g. your local classification society’s country manager , where you explain your proposed method of inspection, is usually more than enough to get an alternative method of testing and inspection accepted. Ask the surveyor what he wants to see demonstrated, well in advance of inviting him on board.

THE NEED FOR IN-HOUSE ACOUSTIC NDE

The old fashioned way of using human eyes and ears to spot impending problems in machinery, overlooks the usefulness of AE ultrasonic transducers to detect structural cracks and to plot predictive trends of machine wear. Just as the human eye can only see a very narrow band of the available light spectrum, so too does the human ear only hear a small sliver of all sounds.

Ultrasonic NDE instruments can “hear” anomalys sound emissions long before the human ear can, making the devices a useful predictive maintenance tool.

How UT Detects Hidden Cracks

API Recommended Practices are about properly evaluating critical
systems before they fail. Ultrasonic transducers accurately plot sound echos
which will indicate an internal crack in a critical load bearing structure,
long in advance of the standard practice of dismantling and visual
inspection. When internal cracks eventually propogate to the surface, they show
up with traditional MPI technologies. But by simply recording the sound of
running bearings, such as a crane slewing ring or crown block cluster,
an ultrasonic sound signature uncovers problems well in advance of any
other technique, short of opening the bearing and having a look.
Acoustic Emissions NDE techniques are commonly used in aviation but
not as widely adopted in oil and gas as they could be.

In other words, through thoughtful use of Acoustic Emissions NDE, many
API inspection requirements can be met without the need for expensive
and risky dismantling of equipment.

Basically, every offshore contractor should be routinely using modern ultrasound
instruments to measure and record trendlines of acoustic signatures. A
qualified NDT person should use this instrument as part of the the PM program which monitor vessel systems. When a third party is required to witness the
inspection records of equipment (such as a 6 monthly API Class III
inspection), these properly maintained NDE records help owners prove that they comply with statutory recommendations.

By employing qualified NDT people to inspect rig components, we
minimize the needless expense of flying 3rd party OEM techs out to the
rig to inspect equipment which our own qualified people have already certified as perfectly good. Wire rope inspection standards works this way – the user is responsible for the good condition of his own equipment.

But all of the foregoing overlooks the more basic point of why has AE
not been more widely adopted into the maintenance of rigs and barges? Is there a kind of dog pack mentality, where nobody dares run ahead of the herd? Or is it plain ignorance, possibly worsened when managers already feel inimidated by the sheer complexity and number of systems on a modern offshore rig?

When marine assets are idle, cash in the bank takes on a different priority, as
contractors look at what they need to do to survive a downturn of
unknown duration. Two new priorities include how to use limited cash
to maintain the integrity of stacked assets and how to keep stacked
rigs as “drill ready” as possible. We need to understand what
technologies could help us “think outside the box” such as adopting
inspection and preservation practices from other industries. We
want to keep our idle assets in good working condition, without excessively
spending down our cash reserves.

The other big difference between cold and warm stacked rigs is the crew. A rig without a crew is vastly less useful than one with a crew. A “smart stacked” rig has a partial crew of key people who are highly familiar with rig systems because they have been operating, inspecting and maintain those systems themselves. Obviously, this small core team comprises the company’s best and brightest individuals of the company’s most knowledgeable and self motivated people, who can help bring up to speed a newly recruited crew

The topic of what comprises the personal qualities of an ideal modern crew needs it’s own article. A new generation jackup, for example, has about 200 critical systems. If the company keeps, say, five key disciplines on the payroll during idle times, how is the knowhow and the work managed across say, mechanic, toolpusher, electrician, barge master, instruments tech? What is the workload? How drill-ready can these five people keep a mothballed modern rig? What does the mothball PM schedule look like?

Our mindsets about how we manage our business have to adapt to new circumstances. Other posts in this series will look further into the changing priorities of those who manage offshore assets in tight times.

Shaun Smithers · 11d ago · Reply · Like · 1
Evan, thanks for a very informative article, I’m particularly impressed with the use of ultrasonics for checking flange bolt tension. The BOP stack has many API flanges anything from 3 to 18 inch or more for surface stacks. There are also hydraulic power fluid flanges that need regularly checking. This method would appear to be far more accurate than just checking for tightness using heavy torque equipment etc.

James Drouin · 10d ago · Reply · Like · 1
a). Yes, it is “true” that cold stacked rigs are NOT “ready to drill”.

b). AE on cold-stacked rigs is a solution in search of a problem.

Bill Ogrady · 11d ago · Reply · Like
Evan,

Great article. As an independent third party, Athens Group deals with the intent and application of classification society rules with respect to the definition of “independent” testing quite often. We have successfully clarified and demonstrated the most cost effective application of independent testing by breaking it down to three elements; (1) the physical tester (the ultrasonic NDE instruments in your example), (2) the test operator, and (3) the test plan.

Our research and practical experience has shown that there’s no defensible argument for a requirement that the test instrument or the test operator be “independent” of the equipment owner. As long as the instrument is capable of making the measurement, and it is maintained and calibrated correctly, the party who owns it is not relevant to a successful test result. Likewise, as long as the operator is trained (certified if necessary) on the operation of the instrument, independence is not an issue. So, as you describe, the equipment owner can also own the test instrument and employ the test instrument operator without negatively impacting the quality of the testing. There is no need to bear the cost of using independently owned instrument sets and independently employed operators in order to achieve the goals of independent testing.

It’s the third element, the test plan where independence becomes critical. In the simplest sense, the test plan is the set of instructions that the test instrument operator will follow, using the test instrument to make the measurement (perform the test). It is a generally accepted system test engineering principle that the person who writes the test plan should be independent of the person who manufactured or owns the unit being tested. Applying this to your interpretation of the class rules, you need to allow the independent third party to go beyond just witnessing the execution of your test. You have to also let them independently review, verify and in some case write/re-write your test plan. If you add this to the scope of the independent third party activities, you will meet the intent of the rule and also achieve a higher quality test.

Roderic Stanley · 11d ago · Reply · Like
I have been a member of the ASNT since 1978. It has amazed me how little NDT is known in some parts of the oil industry. A lot of it is still thought of as black magic, and a lot of it is done by untrained and certified inspectors. Unfortunately, for engineers in the oil industry, most of the universities they have attended do not have courses in it. UT is now relatively common for wall thickness measurement, and the industry has involved into phased array UT (which came out of the medical industry). This is an extremely good technique to use in searching for defects, and often better than radiography. (I am using it in inspecting the bias welds of coiled tubing during manufacture). A UT device based on wall thickness measurement called StressTel was invented many years ago for bolt inspection since sound speed changed with stress. We have used the same physics to look at residual stresses in pipeline welds, and the last engaged thread issues in used drill pipe. Incidentally, the defect shown being isonified in the figure above would reflect most of the sound impinging on it back in a direction such that it might not get back to the transducer.

David Cherbonnier · 11d ago · Reply · Like
Very good article. I especially like the idea of using UT or AE for choke and kill likes. Checking flange integrity by torquing make-up bolts may apply unwanted torque to the flange and piping assembly.